The presence of water or paraffinic hydrocarbons, e.g., waxes, in production fluids may cause problems while transporting a hydrocarbon due to the formation of solids, such as clathrate hydrates or wax deposits, with the hydrocarbons. Clathrate hydrates (hereinafter clathrate or hydrate) are composites formed from a water matrix and a guest molecule, such as methane or carbon dioxide, among others. Clathrates may form, for example, at the high pressures and low temperatures that may be found in pipelines and other hydrocarbon equipment. For any particular clathrate composition involving water and guest molecules, such as methane, ethane, propane, carbon dioxide, and hydrogen sulfide, at a particular pressure there is a specific clathrate equilibrium temperature, above which clathrates are not stable and below which they are stable. After forming, the clathrates can agglomerate, leading to plugging or fouling of the equipment. Further, many hydrocarbons, such as crude oil, may contain significant amounts of wax, e.g., in the form of paraffinic compounds that may precipitate as temperatures are lowered. These paraffinic compounds as well as hydrates can form layers along cold surfaces, such as the inner wall of a subsea pipeline and can cause fouling or plugging of equipment.
Various techniques have been used to lower the ability for clathrates to form or cause plugging or fouling. Exemplary, but non-limiting techniques include insulation of lines, heating of lines, dehydration of the hydrocarbon, and the adding of thermodynamic hydrate inhibitors (THIs), kinetic hydrate inhibitors (KHIs), and/or anti-agglomerates (AAs).
Insulation, active heating, and dehydration can be expensive, especially for subsea systems. Even with insulation, cool-down of production fluids can limit the distance of a producing pipeline. For example, the contents of the pipeline may cool down during shut-in periods and form a clathrate or wax plug. If a clathrate blockage does occur, insulation can be detrimental by preventing heat transfer from the surroundings that is needed for clathrate melting.
Inhibitors, such as thermodynamic hydrate inhibitors (THIs), kinetic hydrate inhibitors (KHIs), and/or anti-agglomerates (AAs), may help mitigate or prevent the formation of clathrate deposits. However, the quantities required for total inhibition, for example, using THIs, may be large and proportional to the amount of water produced, leading to increasing and even prohibitive quantities late in field life. Further, the addition of too low an amount of inhibitor, either THIs or KHIs may actually increase the likelihood of plugging.
An alternative to the use of THIs and KHIs is cold flow technology, in which clathrate can be formed in a manner that prevents clathrate particles from sticking to each other without the use of chemical inhibitors.
Accordingly, research is continuing to identify techniques for preventing clathrate plugging during hydrocarbon transport. For example, some research has been performed on materials that may be used as energy sources to provide heat energy to a system. The formation of clathrates and wax deposits are exothermic, meaning they must release the heat generated while they are forming. Thus, if heat cannot be released, no additional clathrates or wax can form even though the materials may be at their respective equilibrium temperature. This is a common property of many materials, which emit heat, i.e., are exothermic, during a phase change, such as solidification from a liquid. The release of the heat energy maintains the material temperature at some equilibrium value until the phase change is complete. Such a phase change commonly occurs when a system undergoes a change in its physical state such as cooling or pressurizing. In contrast to a clathrate, a salt hydrate is a salt-crystal that contains water molecules associated with the salt crystal, such as CuSO4⋅5H2O. Clathrate hydrates should not be confused with salt hydrates, which are commonly used as phase-change materials, for example, to absorb or provide heat energy.
Phase change materials have been disclosed for use in clathrate/wax mitigation, for example, in the insulation. For example, U.S. Pat. No. 6,000,438 to Ohm discloses an insulation that has an integrated phase change material for subsea flowlines or pipelines that is alleged to have improved transient heat-loss characteristics that may extend a cool down time of hydrocarbon fluid mixtures during shut-in conditions. The phase change material can surround a carrier pipe of the pipeline, and may be dispersed or encapsulated within standard insulation layer. Additional layers or pipes may surround the phase change material and hold it against the carrier pipe. The phase change material can be a micro-encapsulated or bulk-encapsulated type.
U.S. Pat. No. 7,745,379 to Collins discloses a method for insulating subsea pipeline bundles. The insulation is a gelled material, for example an orthophosphate ester to which a ferric salt, such as ferric sulphate, has been added as a gelling agent. Prior to gelling, the materials can be injected into the annulus between a carrier pipe and hydrocarbon carrying tubular line. The gel may contain a phase change material that can provide some heat energy during a shut-in condition.
In both of these patents, the phase change materials are installed as immobile permanent fixtures. The disadvantage of these systems is that the heat must be recovered if the phase change material solidifies, which keeps the system cooled for longer periods of time. Additionally, the remote location of insulation in a subsea application can cause difficulties in maintenance and introduce insulation inadequacies.